1.Field of the Invention
This invention relates to improvements for drill bits, the improvements having the ability to break cuttings produced from drilling operations and to prevent or remove cuttings or drilling fluid solid material accretion on such drill bits. More specifically, this invention relates to drill bits having the dynamic capability, either mechanical, hydraulic or both, to break drill cuttings produced from the formations being drilled into smaller, more easily transported cuttings in the drilling fluids, to remove the drilled material and/or solids therefrom or to prevent accretion of material or solids thereon. The invention is particularly useful with drill bits used in either plastic and sticky rock formations or formations and drilling fluids which tend to build up or accrete on the bits.
2. State of the Art
The clogging of the various fluid courses, surfaces and cavities of drilling accessories, drill bits and the like by the highly ductile cuttings produced from drilling operations in plastic formations, or solids from the formations, or solids from the drilling fluid, is typically referred to as "balling," or "bit balling", if it is a drill bit. The drilling of shales or other plastic types of rock formations has always been difficult for all types of downhole drill bits and particularly when using drag type drill bits. The shales, when under pressure and in contact with drilling fluids, tend to act as a sticky mass, and tend to ball or clog cutting surfaces and cavities of the drill bit, thereby reducing the bit's cutting effectiveness. Other formations, when contacted with particular types of drilling fluid systems, can also cause severe balling problems by the drilling fluid system enhancing or enabling the cuttings from the formation to accrete on the drill bit and drilling accessories.
Also, certain types of formations being drilled when subjected to high hydrostatic drilling fluid pressure, such as hydrostatic drilling fluid pressure generated by highly weighted drilling fluids used at great depths, are highly plastic, generating long, ductile cuttings during drilling operations. Unless such cuttings are effectively broken into more manageable, smaller cuttings, the various fluid courses, surfaces and cavities of the drill bit and drilling accessories become clogged, thereby reducing their effectiveness.
One typical prior art approach which deals with such a drag bit balling problem has been to provide large cutters on the bit with strong drilling fluid hydraulics in the proximity of the cutters in an attempt to remove the cuttings from the cutter faces with high-volume, high-velocity hydraulic jet flow of the drilling fluids. For example, see U.S. Pat. No. 4,116,289.
Another prior art attempt to deal with such drag bit balling problem is illustrated in UK Patent GB 2181173A, to Barr et al., entitled "Improvements In or Relating to Rotary Drill Bits." It illustrates a bladed drag bit with a plurality of cutters on each blade in combination with a nozzle which creates a vortex flow having a peripheral stream extending across the cutting elements and exiting into a gage region of the bit. The cutters are shown in a spaced relationship and a nozzle is azimuthally disposed in front of each blade. The flow from each nozzle is isolated from the flow of other nozzles on the bit by the solid mass of the adjacent blades. This tends to cause isolation of the hydraulics of each vortex pattern, presents a non-cutting bit surface between the cutters to the sticky formation, and does not provide for a directed hydraulic impingement on the chips, which impingement has a tendency to peel the adhered chips from the cutter faces.
Yet another prior art drag bit for cutting plastic rock formations comprises a plurality of large polycrystalline diamond cutters with each large cutter having a nozzle directing the flow of drilling fluids to each large cutter to apply a force to the chip which is cut by the large cutter. The force tends to peel the chip from the face of the large cutter thereby minimizing the tendency of the bit to ball. Such a bit is illustrated in U.S. Pat. No. 4,913,244.
Still another prior art drag bit for drilling shales and sticky formations comprises a bit body, a plurality of blades formed with the bit body extending therefrom, and at least one cutting element, preferably a plurality of cutters, on each blade. Each cutter has a diamond cutting face to reduce the probability of adhesive contact between the cutters and the plastic, sticky rock formations. Each blade defines a cavity between the blade and the body of the bit, thereby permitting the flow of material therethrough. In this manner, hydraulic removal of cuttings is enhanced to avoid bit bailing. To further enhance the hydraulic fluid flow across the bit, one or more nozzles are disposed in the bit body below each of the blades to direct the hydraulic flow of drilling fluids across the cavity and the plurality of cutters disposed on the corresponding blade. Preferably, each nozzle is disposed in the bit body behind the diamond faces of the corresponding plurality of cutters on a blade with respect to the direction of normal rotation of the bit during drilling. In this manner, the chip being sheared from the formation being drilled extrudes upwardly across the diamond face of the cutter to be caught at the upper edge of the cutter by the hydraulic flow from a nozzle located behind the cutter to effectively peel away the chip from the diamond face into the various waterways and junk slots of the bit. Such a bit is illustrated in U.S. Pat. No. 4,883,132.
While such bits may be effective in the drilling of shales and sticky, plastic rock formations, bit balling may still be a problem in some instances as the bit hydraulic flow may not effectively deal with chip removal from the cutter faces of the bit. In some instances, the hydraulic flow may not be sufficient to peel the chips off the cutter faces, may not be sufficient to break the chips after leaving the cutter faces, or may not be sufficient to cause the removal of large chips, or the instantaneous removal of a high volume of chips, from the waterways, face junk slots and junk slots of the bit during drilling operations.
In other instances, the adhesion properties of the components of various drilling fluid systems are sufficient to cause accretion of the drilling fluid solids and attendant formation cuttings on the drill bit surfaces, thereby affecting the drilling performance of the bit drilling tools and initiation of bit balling. These problems can similarly affect the performance of drilling accessories used in drilling operations.
Another prior art drill bit illustrated in U.S. Pat. No. 4,727,946 utilizes brush-like rubbing pads having a plurality of bristles to provide sealing around the nozzles of the bit face and channel the drilling fluid from the nozzles past the cutting elements of the bit to help clean the cutting elements.
A drill bit described in U.S. Pat. No. 5,199,511 utilizes an expanding pad to sealingly engage the side of the borehole to seal freshly cut portions of the bottom of the borehole from drilling fluids. The expanding pad of the bit body is formed of an elastomeric material which is reinforced with wire or other reinforcing material and which may have an abrasion-resistant grit embedded therein and/or abrasion resistant pad thereon.
A downhole tool described in U.S. Pat. No. 4,744,426 is positioned intermediate the mud motor and drill bit to reduce the hydrostatic pressure of the drilling fluid column near or around the drill bit by pumping the drilling fluid up the annulus between the drill pipe string and the borehole in an attempt to increase bit penetration rate of the formation. A multi-vane fan contained within a portion of the downhole tool is used to pump the drilling fluid up the annulus.